The present Invention relates to hydrocarbon production, particularly to methods of enhancing gas production from shaly formations having high water saturations, and more particularly to reducing water saturations in the formation immediately surrounding either a wellbore or a fracture face by treating the formation with surfactants having good oil-wetting characteristics in the presence of shale. Reduction of water saturation increases the flow of hydrocarbons in these formations. The methods may be used in drilling, completion, stimulation (acidizing or acid fracturing or hydraulic fracturing), remediation or workover, and in enhancing flow from natural fractures or from unstimulated formations.
The present Invention relates generally to hydrocarbon (petroleum and natural gas) production from wells drilled in the earth. Hydrocarbons are obtained from a subterranean geologic formation (i.e., a xe2x80x9creservoirxe2x80x9d) by drilling a wellbore that penetrates the hydrocarbon-bearing formation. In order for the hydrocarbons to be produced, that is, travel from the formation to the wellbore, and ultimately to the surface, at rates of flow sufficient to justify their recovery, a sufficiently unimpeded flowpath from the subterranean formation to the wellbore, and then to the surface, must exist or be provided. Obviously, it is desirable to maximize both the rate of flow and the overall amount of flow of hydrocarbon from the subsurface formation to the surface, where it can be recovered.
Hydrocarbon production is typically limited by two major reservoir factors: porosity and permeability. Even if the porosity is adequate, the effective permeability to the hydrocarbon may be limited. When more than one fluid is present in a permeable system, the flow of each is affected by the amount and distribution of the other(s); in particular the relative flows are affected by which fluid is the xe2x80x9cwettingxe2x80x9d phase, that is the fluid that coats the surfaces. Depending upon many factors, one fluid may flow while another does not. The result of stagnant fluid in the formation naturally diminishes the rate of hydrocarbon recovery. The reasons for this are both simple and complex. Most simply, the presence of fluid, in particular water or brine, in the formation acts as a barrier to the migration of hydrocarbon from the formation into the wellbore. More precisely, aqueous-based fluid injected during well treatments may saturate the pore spaces of the treated region, preventing the migration of hydrocarbon into and through the same pore spaces. In an analogous manner, if the well is to be produced without first stimulating, naturally occurring aqueous fluids in the formation in the flowpath or potential flowpath may hinder the production.
Indeed, diminished effective permeability caused by stagnant fluid often limits hydrocarbon production (both rate and capacity) from a given well. To achieve an increase in well productivity therefore involves removing stagnant fluid from the formation. No completely satisfactory method exists to remove these fluids, and therefore prevent them from reducing production.
In the natural state, formations may be oil-wet, water-wet or of mixed wettability, depending upon the nature of the fluids and the formation. (In this and following discussions, xe2x80x9coil-wetxe2x80x9d is meant to include surfaces that are xe2x80x9cwetxe2x80x9d by adsorbed, condensed or compressed gas as well.) When the internal surface of an oil or gas producing formation or fracture face pore is oil-wet, the oil phase will occupy the pore surface as well as the smallest, least permeable flow paths. As such, the oil or gas will have to flow through a restricted pathway to be produced, and the water, which is non-wetting, will be able to flow through the high permeability, least restricted, flow path. Therefore, in order to maximize oil or gas flow capacity, it is generally preferred that the pore surface be water wet.
One exception to that recommendation has been the specific case of the recovery of methane from coal seams. In such types of formations, most gas in coal is adsorbed onto the very high internal surface area of the oil-wet organic constituents of the coal, and consequently, coals are described as being normally oil-wet, unlike in conventional gas reservoirs that are composed of inorganic minerals that are normally water-wet. In U.S. Pat. No. 5,229,017, Nimerick et al. teach that treating coal formations with dewatering agents to create persistent oil-wet coal surfaces enhances gas production by reducing the tendency of formation fines migration and increasing the drainage of water from the formation. More specifically, Nimerick et al. disclose the use of some organic surfactants selected from butylene oxide derivatives or polyethylene carbonates for hydraulic fracturing.
However, Nimerick et al. do not address other conventional reservoir operations such as drilling, completion, remediation, acidizing, acid fracturing, or enhancing flow in natural fractures, nor do they address treatment of conventional gas reservoirs that are normally water-wet or have become water-wet, or in which the producible hydrocarbons are in a porous mineral matrix such as shale formations like the Devonian Shale and the Barnett Shale. For those conventional formations, the common prejudice remains that water-wet surfaces are preferable.
It has been observed that when the formation is a shale that has a high water content, production of hydrocarbons, particularly if they are in the formation substantially as adsorbed, condensed gas, may be delayed and slow. The problem typically occurs in gas wells such as those in shale formations that contain high concentrations of adsorbed gas, primarily natural gas (that we will refer to as xe2x80x9cmethanexe2x80x9d in the following discussions), as opposed to those that contain primarily compressed but not adsorbed gas. For those wells, it is imperative to remove the water as quickly and completely as possible to maximize production rate and total methane recovery. In this way the operator can apply maximum pressure drawdown in the formation rather than in the wellbore. Water in the formation impedes gas desorption and flow.
For those shaly formations containing adsorbed hydrocarbon gas, the inventors have found that it would be acceptable for the formation to be oil-wet during gas productions because this allows the water to be removed more quickly and more completely and open more of the pore to gas flow. It is also advantageous to minimize fines migration, since fines block flow paths throughout the production system, from the formation to downhole equipment to surface equipment. In general, these same factors and arguments, with appropriate modification to suit the specific situations, pertain to stimulation (acidizing or acid fracturing or hydraulic fracturing), remediation or workover, and in enhancing flow from natural fractures or from unstimulated formations.
There are many oil and gas well operations in which the formations are oil-wet or become oil-wet and the presence of significant amounts of water in pores or fractures is detrimental. The common denominator of the methods encompassed in this Invention is that they all deal with enhancing the recovery of hydrocarbons from subterranean formations that contain adsorbed and compressed hydrocarbon gases, especially methane, in shale rich matrixes and that the enhancement is accomplished by causing the formation to be or to remain oil-wet, thus promoting dewatering of the shale and maximizing flow paths for the hydrocarbons. By xe2x80x9ccausing the formation to be or to remain oil-wetxe2x80x9d, we mean that if the formation is water-wet it becomes oil-wet and continues to be oil-wet while a sufficiently large volume of water or brine flows through and is removed from the formation to produce the results desired from the treatment method, and if the formation is oil-wet it continues to be oil-wet while a sufficiently large volume of water or brine flows through and is removed from the formation to produce the results desired from the treatment method. By xe2x80x9cadsorbed and compressedxe2x80x9d gas we mean that the formation contains adsorbed gas on surfaces and additional gas contained within the formation pores in a compressed state.
We have discovered that specific types of dewatering agents that leave a long-lasting oil-wet surface substantially increase the dewatering of shale, speed up the production of gas, and increase the total gas produced. In particular, those agents comprise:
(a) organic surfactant compounds having the formula R1-(EOx-PrOy-BuOz)H wherein R1 is an alcohol, phenol or phenol derivative or a fatty acid having 1 to 16 carbon atoms, EO is an ethylene oxide group and x is 1 to 20, PrO is a propylene oxide group and y is 0 to 15, and BuO is a butylene oxide group and z is 1 to 15;
(b) an organic polyethylene carbonate having the formula
R2-(xe2x80x94CH2-CH2-Oxe2x80x94C(O)xe2x80x94Oxe2x80x94)qH 
wherein R2 is an alcohol having 7 to 16 carbon atoms and q is 7 to 16;
(c) butoxylated glycols having 1 to 15 butylene oxide groups;
(d) ethoxylated-butoxylated glycols having 1 to 5 ethylene oxide groups and 5 to 10 butylene oxide groups; and
(e) alkyl-aminocarboxylic acids or carboxylates.
These dewatering agents have good oil-wetting characteristics. The ability to reduce the water saturation in a gas containing shale will increase the relative permeability to gas in the formation. This increased permeability to gas will improve well performance and substantially improve the economic value of oilfield treatments employing fluids that contain these dewatering agents. Tenacious adsorption of the dewatering agent onto the shale surface maintains an oil-wet condition, thus facilitating reduction of the water saturation in the shale. Surfactants that result in water-wet formation surfaces will not be suitable.
One embodiment is a method for dewatering a shaly hydrocarbon bearing subterranean formation comprising adsorbed and compressed gas comprising the steps of contacting the formation with an effective amount of a well treatment fluid comprising one or more than one of a dewatering agent that causes the formation to be and to remain oil-wet; and removing water from the formation.
Another embodiment is a method for enhancing gas production from a shaly hydrocarbon bearing subterranean formation comprising adsorbed and compressed gas comprising the steps of contacting the formation with an effective amount of a well treatment fluid comprising one or more than one of a dewatering agent that causes the formation to be and to remain oil-wet; removing water from the formation; and removing gas from the formation.
Still another embodiment of the present Invention is a method of hydraulically fracturing a shaly subterranean formation containing high concentrations of adsorbed and compressed gas. This method comprises the step of injecting the well treatment fluid composition of the Invention via a wellbore into the formation at a flow rate and pressure sufficient to produce or extend a fracture in the formation. The well treatment fluid comprises one or more surfactants that create or maintain an oil-wet surface. The dewatering agents will be particularly effective at promoting the recovery of the injected fracturing fluid from the formation near the fracture face where it was driven into the pores during the hydraulic fracturing treatment. Moreover, the water containing surfactant can also contain a wide variety of functional additives that are known to improve the performance of fracturing treatments. Such functional additives include polymers, crosslinkers, breakers, biocides, scale inhibitors, proppant, and others.
Other embodiments of the present Invention provide a remedial treatment or workover of gas wells in a shaly subterranean formation containing high concentrations of adsorbed and compressed gas to enhance dewatering and the production of gas. These methods comprise the step of injecting, into a well that has been producing for some time and may or may not already have been stimulated (fractured and/or acidized) in the past, and may contain natural fractures, the well treatment fluid composition of the Invention via a wellbore into the formation at a flow rate and pressure less than the fracturing pressure.
Further embodiments comprise acidizing and acid fracturing in shaly subterranean formations containing high concentrations of adsorbed and compressed gas, that is methods as described above in which the injected fluid promotes dewatering and further comprises an acid and is injected either above or below the formation fracture pressure.
Yet another embodiment is a drilling or completion fluid comprising one or more of the shale dewatering agents described above.
These and other embodiments may use foamed or energized fluids if the selected surfactants are known to create stable foams, or if the fluids further comprise foamers and the selected surfactants are not anti-foamers.
Other embodiments will be apparent to those skilled in the art of production of subterranean fluids.
In accordance with the Invention, an aqueous well treatment fluid is used in well treatment of shaly formations containing adsorbed and compressed hydrocarbon gases. In the term xe2x80x9cwell treatmentxe2x80x9d we include drilling, completion, remediation, stimulation (acidizing or acid fracturing or hydraulic fracturing), and enhancing flow from natural fractures or from unstimulated formations. Any of these well treatments, except of course drilling and the drilling portion of completion, may be repeated if desired or necessary in the normal course of management of a well or reservoir. Various oilfield treatments often must be repeated because of changes in flow patterns or rates, often in turn caused by changes in temperature or pressure or by deposition of scales, paraffins, asphaltenes, etc. The treatments of this Invention may include the first time such a treatment is performed in a given well or formation or a subsequent treatment (in which case the first treatment may or may not have been performed according to the methods of this Invention). The fluid includes a dewatering agent for facilitating the removal of water from the formation, the fracture or acidized face, if there is one, and the region of the formation near the fracture, acidized region or wellbore.
In the following discussion, by xe2x80x9cshalexe2x80x9d we mean a compacted sedimentary formation in which the constituent mineral particles are predominantly very fine clay, silt or mud but may contain small amounts of other materials such as sandstone, carbonates or kerogen. By xe2x80x9cshalyxe2x80x9d we mean formations in which the mineral content is greater than about 40% clay or shale, as opposed to sandstone or carbonate. By xe2x80x9ccoalxe2x80x9d we mean a combustible rock composed primarily of plant material compressed and altered by time, pressure and temperature into an organic material having a high carbon content; coal may contain some shale or other minerals. By xe2x80x9cwaterxe2x80x9d we mean an aqueous fluid that may contain organic or inorganic; indigenous or added; solid, liquid or gaseous materials dissolved or suspended therein, such as salts, carbon dioxide, nitrogen, alcohols, water-miscible components of petroleum, etc. Most particularly by water we mean formation water or brine or aqueous wellbore treatment fluids.
Treatment of shaly reservoirs that contain significant concentrations of adsorbed gas requires techniques quite different from those used in conventional sandstone or carbonate reservoirs. The well treatment methods are applicable to formations in which from about 1% to about 100% of the hydrocarbon gas is adsorbed hydrocarbon gas (particularly methane) especially from about 5% to about 100%, and most particularly from about 20% to about 100%. As the pressure in the formation is reduced, at a certain pressure, the critical methane desorption pressure governed by the Langmuir desorption isotherm, the methane will begin to desorb from the formation. In addition, such formations are often substantially or completely saturated with water. In these cases, large quantities of water must be removed in order to lower the reservoir pressure to a point below the critical methane desorption pressure. Therefore, a well treatment carried out in such a formation must be designed to produce water effectively. Maintaining the shale in an oil-wet state facilitates water production.
Normally, as was discussed above, it is believed by those skilled in the art of recovery of hydrocarbons from conventional (as opposed to coal) subterranean formations that it is most preferable to maintain the formation in a water-wet condition. References discussing the effect of formation wettability on oil production include: Anderson, William G., Wettability Literature Survey-Part 5: The Effects of Wettability on Relative Permeability, Journal of Petroleum Technology 1453-1468 (November, 1987); Anderson, William G., Wettability Literature Survey-Part 6: The Effects of Wettability on Waterflooding, Journal of Petroleum Technology, 1605-1621 (December, 1987); McLeod Jr., Harry O., Matrix Acidizin, Journal of Petroleum Technology, 2055-2069 (December, 1984); and Ribe, K. H., Production Behavior of a Water-Blocked Oil Well, SPE 1295-G (1959).
Moreover, the following reference teaches methods of ensuring that formations are water-wet. Gidley, J. L., Stimulation of Sandstone Formations with the Acid-Mutual Solvent Method, Journal of Petroleum Technology, 551-558 (May, 1971). The following references describe the effects of wettability in gas producing formations: Holditch, S. A., Factors Affecting Water Blocking and Gas Flow from Hydraulically Fractured Gas Wells, Journal of Petroleum Technology, 1515-1524 (December, 1979); and Baker, B. D. and Wilson, J. C., Stimulation Practices Using Alcoholic Acidizing and Fracturing Fluids for Gas Reservoirs, SPE Paper 4836, presented at the SPE European Spring Meeting held in Amsterdam, The Netherlands, May 29-30, 1974.
However, we have found that under certain circumstances maintaining the formation in an oil-wet condition is preferred.
In accordance with the Invention, the dewatering agent is an organic surfactant selected from a group consisting of:
(a) organic surfactant compounds having the formula R1-(EOx-PrOy-BuOz)H wherein R1 is an alcohol, phenol or phenol derivative or a fatty acid having 1 to 16 carbon atoms, EO is an ethylene oxide group and x is 1 to 20, PrO is a propylene oxide group and y is 0 to 15, and BuO is a butylene oxide group and z is 1 to 15;
(b) an organic polyethylene carbonate having the formula
R2-(xe2x80x94CH2-CH2-Oxe2x80x94C(O)xe2x80x94Oxe2x80x94)qH 
wherein R2 is an alcohol having 7 to 16 carbon atoms and q is 7 to 16;
(c) butoxylated glycols having 1 to 15 butylene oxide groups;
(d) ethoxylated-butoxylated glycols having 1 to 5 ethylene oxide groups and 5 to 10 butylene oxide groups; and
(e) alkyl-aminocarboxylic acids or carboxylates.
Where the surfactants contain one or more than one of ethoxy, propoxy and butoxy units, the exact order of these units within the molecule is not critical. Since the R group can be derived from a natural product, the R group can have a distribution of carbon atoms. Surfactants useful in the present Invention include those described by Nimerick et al. in U.S. Pat. No. 5,229,017 (assigned to Schlumberger Technology Corporation). This patent is hereby incorporated by reference in its entirety. A process for preparing organic polyethylene carbonates is given in U.S. Pat. No. 4,330,481. This patent is hereby incorporated by reference in its entirety. The surfactants in a) and b) above are described here with slightly different structural formulas than in U.S. Pat. No. 5,229,017.
Other surfactants that are useful in the present Invention are described in U.S. patent application Ser. No. 09/513,429 by England et al. (filed Feb. 25, 2000; assigned to Schlumberger Technology Corporation) which describes several foaming agents for release of methane from coal that have similar functional properties as the organic surfactants in U.S. Pat. No. 5,229,017. That application describes methods that require surfactants that are effective both for oil-wetting and for foaming. The surfactants of that application that provide oil-wetting, and only those that provide oil-wetting, will be effective in the present Invention whether or not they provide foaming. In fact, one class of surfactants (alkyl-aminocarboxylic acids or carboxylates), which was shown in that application to be not applicable, is applicable in the present Invention. U.S. patent application Ser. No. 09/513,429 is hereby incorporated by reference in its entirety
Particularly preferred examples are alcohols substituted with ethylene oxide and butylene oxide (such as butanol having about 3 ethylene oxide units and about 5 butylene oxide units); di-secondarybutylphenol having about 5 ethylene oxide units and about 4 butylene oxide units; decanol having about 10 ethylene carbonate units; a mixture of diethyleneglycol monobutyl ether, triethyleneglycol monobutyl ether and higher glycol ethers having about 4 ethylene oxide units and about 6 butylene oxide units; tridecyl alcohol having about 7 to 8 ethylene oxide and about 3 to 4 butylene oxide units; tridecyl alcohol having about 7 ethylene oxide units and about 1 to 2 butylene oxide units; and triethylene glycol monobutyl ether-formal, which has the formula (BuO(xe2x80x94CH2-CH20)3)2CH2.
Another suitable surfactant comprises an alkyl-aminocarboxylic acid or carboxylate, more preferably an alkyl-aminopropionic acid or propionate. In one particular embodiment, the surfactant has the formula
Rxe2x80x94NHxe2x80x94(CH2)nxe2x80x94C(O)OX 
wherein R is a saturated or unsaturated alkyl group having from about 6 to about 20 carbon atoms, n is from 2-6, and X is hydrogen or a salt forming cation. In various specific embodiments of the Invention, n can be from 2-4, most preferably 3; and R can be a saturated or unsaturated alkyl group having from about 6 to about 20 carbon atoms. Since the R group can be derived from a natural product, the R group can have a distribution of carbon atoms. One particular preferred surfactant is coco-aminopropionate.
Methods of drilling, stimulation (acidizing or acid fracturing or hydraulic fracturing), remediation or workover, and of enhancing flow from natural fractures or from unstimulated formations are well known to those skilled in the art of production of subterranean fluids. Drilling involves rotating a drill bit at the end of a drill string in a well while circulating a well treatment fluid (the drilling fluid). The drilling fluid functions to carry cuttings to the surface, to cool and lubricate the bit, and to control the flow of fluids from the wellbore into the formation or from the formation into the wellbore. Completion is drilling into the productive formation and carrying out certain steps to end the drilling process and enable hydrocarbon production from the desired zones. Remediation and workover are operations (such as deepening, pulling and resetting liners, etc.), performed to increase production from wells. Acidizing is treating a formation with acid to increase production by etching the rock, removing soluble damaging materials, and enlarging the pore spaces and passages. Hydraulic fracturing will be described in detail below. If hydraulic fracturing is carried out with an acidic fluid, it is referred to as acid fracturing. Reasons and methods for selecting all these methods and fluids for these methods, in particular for their chemical and physical properties relative to the formation, are well known to those skilled in the art of production of subterranean fluids.
The effective amounts of the surfactants of the present Invention can readily be determined by such persons without undue experimentation. These surfactants can be used over a wide range of concentrations, typically from 0.01 volume percent to 10 volume percent, but preferably between 0.05 volume percent to 10 volume percent, and most preferably between 0.05 volume percent to 0.5 volume percent of the treatment fluid. (Note that 1 volume percent is equivalent to 10 gallons per thousand gallons (gpt).) Similarly, the choice of surfactant can readily be made by commonly known methods by those skilled in the art of production of subterranean fluids upon evaluation of the nature of the surfaces and fluids (both indigenous and injected) involved, including taking into consideration other chemicals present in the indigenous or injected fluids and whether or not the treatment fluid is to be foamed or energized. The surfactants can be blended directly with fluids used in the various wellbore treatments listed above as the fluids are first formulated, or the surfactants may first be prepared as concentrates, particularly aqueous concentrates, and the concentrates then used in the preparation of the final fluids.
One example of a well treatment method of the Invention is hydraulic fracturing of a subterranean reservoir. Hydraulic fracturing is a standard practice for increasing oil or gas production from subterranean reservoirs. A wide variety of treatment designs are applied depending on the specific characteristics of the formation, the quality of the reserves, and the operating environment. However, all treatments share the requirements of creating new inflow surface area and ensuring that there is good hydraulic conductivity and connectivity between the wellbore and the reservoir. Any damage to the hydraulic fracture and to the formation surrounding the fracture can reduce the hydraulic conductivity and connectivity, thereby reducing the ability of the newly created inflow surface to allow passage of the desired quantities of oil and gas. Fracture damage takes many forms, but is located either in the fracture itself or in the formation immediately surrounding the fracture (the fracture face).
Fractures are most typically initiated using 1 to 4 gallons of a selected dewatering surfactant in accordance with the Invention per 1000 gallons of water. The water may be neat or a brine and may also contain low amounts of a polymeric (natural or synthetic) viscosifying agent. This stage, the pad, has high water leak-off (dependent upon permeability and differential pressure) into the formation and primarily is intended to initiate the fracture or fractures and to place the initial quantities of the dewatering surfactant in the formation. Following fracture initiation, additional fracturing fluid is pumped to attain wider fractures; this fluid typically contains higher polymer loadings (up to 40 to 60 lbs per thousand gallons). The polymer may be either crosslinked or uncrosslinked.
The well treatment fluid of the present Invention may also be used for remediation, that is to enhance water and gas recovery from xe2x80x9cpoorxe2x80x9d producers that have previously been fractured and propped, or wells which contain some conductive drainage channels to the wellbore. In this treatment, water having little or no polymer loading is used to transport 2 to 4 gallons of the selected dewatering surfactant per 1000 gallons of fluid into the formation. This treatment is normally done at less than fracturing pressure to prevent dislodging the proppant that may be present in the fracture. The total volume of fluid containing the dewatering surfactant would depend on the formation height and the desired penetration of the treating fluid containing the dewatering surfactant.
The surfactants of the present Invention are adsorbed onto the surfaces, thereby increasing the hydrophobicity of the shaly formation. The preferred surfactants also are relatively tenaciously bound to the surfaces thereby preventing re-wetting and re-adsorption of water on the surfaces by the passage of subsequent volumes of water during the fracture fluid cleanup, formation drainage and hydrocarbon production processes. Thus the benefits can be realized over an extended period of hydrocarbon production. This feature of the surfactants offers the additional advantage that, since the surfactants are tenaciously bound to the surfaces, minor, if any, amounts are contained in the produced water, thereby greatly reducing any environmental discharge problems associated with the produced water. Further, the surfactants of this Invention inhibit the migration of fines within the formation, fracture face and fracture, thereby additionally enhancing and maintaining fracture conductivity.
Of course, all surfactants would eventually be washed off of any surface by a sufficiently large volume of surfactant-free water or brine. Satisfactory performance in the methods of this Invention is achieved if the surfactant remains on the surface long enough to achieve the desired results of a specific treatment. In particular, it should be noted that satisfactory performance, as measured by how tenaciously the surfactant is bound to a formation surface, could be different for surfactants that are also foaming agents as opposed to surfactants that are not. Treatment fluids are sometimes foamed or energized with gases for various reasons, such as to achieve some other more desirable result(s), such as to lighten the hydrostatic load during and after the treatment, use less base fluid, do less damage to the formation or to do less damage to a proppant pack or gravel pack, etc. While there is no intention to be bound by any theory of invention, it is believed that the surfactants of the Invention that are good foamers are inherently less strongly adsorbed to formation surfaces than are surfactants that are non-foaming or are anti-foaming agents. Thus when using surfactants that are known to create stable foams, a sufficiently large volume of water or brine flowing through and being removed from the formation to produce the results desired from the treatment method, might be less than the volume acceptable with a surfactant that does not create a foam. This affect could be offset, if desired, by using a higher concentration of the surfactant in the treatment methods, or by repeating the treatment methods, as appropriate.
The present Invention can be further understood from the following laboratory experiments. A preferred surfactant of the Invention, Surfactant A, a product comprising branched tridecyl alcohol having about 7.5 ethylene oxide units and about 3.5 butylene oxide units, commercially available from Schlumberger, was used to illustrate the effectiveness of the surfactants of the Invention for minimization of fracture face skin in shale formations.